1. Field of the Disclosure
Embodiments disclosed herein generally relate to drill bits used in drilling subterranean formations. Other embodiments relate to the design of drill bits, including variations in nozzle size, nozzle orientation, and fluid guide configurations, which may be optimized to provide enhanced cuttings removal from a wellbore. In still other embodiments, the present disclosure relates to apparatuses and methods to improve the efficiency of hydraulic cleaning around the drill bit during drilling operations.
2. Background Art
Conventional drilling systems typically include the presence of a drill bit connected at the bottom of a rotatable drillstring. FIGS. 1A-1D together illustrate a drilling system 101 that uses a drill bit 109 to drill a wellbore 105 in a subterranean formation 103. As shown in FIG. 1A, a rotary table 98 or other device (e.g., top drive, etc.) is used to rotate the drillstring 102, which results in a corresponding rotation of the drill bit 109 at the end of the drillstring 102. FIGS. 1B and 1C show the drill bit 109 includes a bit body 114 secured to a steel shank 123 and a pin connection 124, which are configured to connect the drill bit 109 to the drill string 102. The bit body 114, which includes a bit face 115, is fitted with cutting structures (e.g., blades) 116 that are configured to cut (i.e., dig, crush, shear, etc.) into the formation 103.
Generally, if the bit 109 is a fixed-cutter, or “drag” bit, the cutting structures 116 will have a plurality of cutting elements 118, such as cutters, inserts, PDC inserts, compacts, etc. These cutting elements 118 have cutting surfaces formed of an abrasive material, such as, for example, polycrystalline diamond compacts (“PDCs”), thermally stable polycrystalline diamond compacts (“TSPs”), natural diamonds, as well as cubic boron nitride compacts, and are oriented on the bit face 115 in the direction of bit rotation. A drag bit body is usually formed of machined steel or a matrix casting of hard particulate material such as tungsten carbide in a (usually) copper-based alloy binder. The cutting elements 118 may be secured to the blades 116 and/or the bit body 114 as would be known to one of ordinary skill in the art, such as during a furnacing operation or a brazing process.
The typical drilling system 101 also provides drilling fluid (e.g., “drilling mud,” “mud,” etc.) 111 that is transported down the drill string 102 and into the drill bit 109. Surface equipment 113, such as pumps, is used to create pressure and flow rate to circulate the drilling fluid 111 thru the drillstring 102. The drillstring 102 typically has an internal bore or flow passage 103a that extends from, and is in fluid communication between, the surface equipment 113 and the drill bit 109. The size (e.g., diameter) of the drillstring 102 with respect to the wellbore 105 defines an annulus 106 that allows for return of drilling fluid and any entrained cuttings (e.g., formation cuttings, other debris, etc.) to the surface.
Referring to FIGS. 1A-1C together, the drilling fluid 111 is pumped from, for example, a mud pit 112, into the internal bore 103a, and down to the drill bit 109 through a bit inlet 130 and fluid cavity or plenum 126. The drilling fluid 111 flows from the plenum 126 through one or more internal channels or bores 128, and out of the drill bit 109 via one or more nozzles 122 (and corresponding orifice) in connection therewith. The pressure of the drilling fluid 111 as delivered to the bit face 115 through the nozzles 122 (or other ports, openings, etc.) must be sufficient to overcome the hydrostatic head at the drill bit 109, and the flow velocity must be sufficient to carry the drilling fluid 111 (along with entrained cuttings) away from the bit face 115, through the annulus 106, and to the surface 107.
As drilling fluid 111 exits the drillstring 102, the fluid enters the plenum 126 of the drill bit 109. The velocity of the drilling fluid 111 that enters the plenum 126 is usually relatively low, but as the fluid enters the orifice 122a of the nozzles 122 the fluid velocity increases substantially as a result of the reduction of exit area in the orifice. The nozzles 122 are typically placed at or near the bit face 115 for various purposes, whereby the fluid performs several functions, such as cooling the drill bit 109, evacuating cuttings from the bit 109 to the surface 107, and providing wellbore integrity.
These functions are extremely important in order for the drill bit 109 to efficiently cut the formation 103 over a commercially viable drilling interval. Because of the weight on bit (WOB) applied by the drillstring 102 as necessary to achieve a desired rate of penetration (ROP), there is substantial frictional heat generated on the bit face 115. As a result, the drilling fluid 111 is necessary and essential to cool the drill bit 109. Without the drilling fluid 111, the drill bit 109, including the bit face 115 and the cutting elements 118, would structurally degrade and prematurely fail.
The drilling fluid 111 is also vital for the removal of cuttings and/or other debris from the bit face 115. Stationary cuttings around the bit face 115 impede the cutting efficiency of the drill bit 109 by obstructing the access of the cutting elements 118 to the formation 103. In addition, stagnant flow around and above the drill bit 109 contributes to inefficient removal of cuttings from the bit face 115 because of inadequate flow regimes around the drill bit 109. Stagnant or reduced flow of drilling fluid 111 also results in less-effective cooling of the cutting elements 118 in areas where the flow is impeded.
These conditions often lead to “bit balling,” whereby without removal of the cuttings, the cutting elements 118 (and the bit face 115) ball up with material cut from the formation 103. It is recently recognized that bit balling originates or initiates at the gage area (i.e., side) 138 of the bit body 114. Once the gage area 138 is blocked and clogged, the mass of formation cuttings builds back down toward the bit face 115 and/or onto the face, until the drill bit 109 completely balls. Bit balling renders the drill bit 109 as unable to effectively engage and further penetrate into the formation 103 to advance the wellbore 105.
Modern drill bits typically include “junk slots” 165 formed on the exterior of the bit body 114 to aid flow patterns around the drill bit 109. The junk slot 165 is usually adjacent to and/or between corresponding bit blades 118, such that the junk slots 165 are configured for the drilling fluid 111 to flow from the nozzles 122 disposed in the bit face 115, past the drill bit 109, and to the annulus 106 above the drill bit 109. The intent of the junk slots 165 is to promote and pass the flow of drilling fluid 111 along each corresponding blade 118. However, the position and angular orientation of any nozzle 122 may be different, whereby the magnitude and orientation of flow energy of the drilling fluid varies from one junk slot to the next, which usually leads to inefficient and uneven distribution of hydraulic energy.
For example, a relatively higher flow pressure may generate an adjacent zone or area of relatively lower hydraulic pressure. When this occurs, drilling fluid that emanates from a particular nozzle that would ideally flow past the desired cutting elements of a particular blade and up through the associated junk slot may actually be pulled or drawn downward into a low pressure zone created by a flow regime of another junk slot. In effect, some of the junk slots 165 will have a positive or upward flow of drilling fluid, while others will have a negative or downward flow, which is detrimental to the intended desired flow pattern in the junk slots. In typical prior art drill bits this results in stagnant flow regions in and above the junk slots, usually adjacent, behind and above the blades because of the inefficient distribution of drilling fluid.
FIG. 1D illustrates an example of a stagnant flow regime 171 that leads to a build up and/or uneven distribution of cuttings 132 in certain areas of the wellbore 105. This may be especially troublesome in directional or horizontal drilling where the effects of gravity cause further separation and/or settling of cuttings (or other debris) 132. The cuttings generated during the drilling process that would normally flow up through the annulus 106 may circulate from a positive flowing junk slot to a negative flowing junk slot, or may accumulate adjacent or above a blade in regime 171, the result in either case thereby leading to bit balling of the drill bit 109.
The aforementioned phenomenon of bit balling has become a more serious problem in recent years. The design of newer bits often includes the use of superabrasive cutters in order to achieve higher ROP. However, while marked increases in ROP have been achieved, the inability of drill bits to clear formation cuttings at a rate commensurate with the bits' ability to generate such cuttings has proven to be a troublesome limitation to further increases in ROP. On modern, technically sophisticated drill bits, the number of nozzles 122 on the bit face 115 is typically one per blade. The limitations on the number of nozzles on a drill bit are due not only design and manufacturing constraints, but also due to surface equipment capabilities.
As such, prior art drill bits have failed to consider and appreciate the tendency of poor cuttings clearance from the drill bits as a result of the consequent balling of the bit, and improvements usually focus on incorporating design features at the bit face or plenum areas of the drill bit. However, these improvements seldom lead to higher drill bit efficiency.
As a result, there is a need for a drill bit designed to minimize balling, as well as a drill bit and/or other drilling-related structures that provide enhanced hydraulic characteristics and the advantages associated thereof. There is a need for a drill bit that enhances the hydraulics around the drill bit in areas other than the bit face.
There is a great need to provide enhancements to formation cuttings clearance for drill bits through design improvements that may be implementable in any drill bit. There is a need for enhanced formation cuttings clearance through optimized distribution of hydraulic energy in the form of drilling fluid. Such apportionment may be achieved by employing nozzles of differing aperture sizes and in association with fluid guides and blades configured to evenly distribute drilling fluid in, around, and above the drill bit.
There is a need to create an upwardly directed flow of fluid away from the drill bit that removes impingement of drilling fluid and cuttings against the bit face. The upwardly directed flow induces flow paths away from the bit face and optimizes fluid particle distribution, flow regime, and pressure distribution in areas above the drill bit. There is a further need to create a synergistic method of optimizing hydraulic flow by utilizing hydraulic energy at the bit face coupled with the flow traveling away from the bit. Such apportionment may be achieved by fluid guide geometry and orientation.